US20150107834A1

US20150107834A1 - Method for producing heavy oil

Info

Publication number: US20150107834A1
Application number: US14/518,880
Authority: US
Inventors: Chonghui Shen; Jorge Luis Lopez; Liping JIA; Sepehr ARBABI-TEHRAN
Original assignee: Shell Oil Co
Current assignee: Shell USA Inc
Priority date: 2013-10-23
Filing date: 2014-10-20
Publication date: 2015-04-23
Also published as: CA2868189A1

Abstract

A method is provided for production of heavy oil from a reservoir containing heavy oil, the method including the steps of: providing a plurality of wells into the formation; injecting into the plurality of wells a mixture comprising steam and a solvent; ceasing injection of the mixture; producing a mixture of heavy oil, solvent and condensed steam from the plurality of wells after injection of steam has ceased: and after production of the mixture of heavy oil, solvent and condensate from at least one of the plurality of wells has declined to a predetermined rate, injecting into the at least one well a stream consisting essentially of steam while at least one other well continues to operate as a producing well.

Description

RELATED CASES

This application claims the benefit of U.S. Provisional Application No. 61/894,681, filed on Oct. 23, 2013, which is incorporated herein by reference.

BACKGROUND

The invention relates to a method for producing heavy oil from a formation by co injection of steam and solvent.
Reservoirs of heavy oil can be challenging to produce because heavy oils can have viscosities, at the ambient temperatures of the reservoirs, that render the oils essentially immobile. To produce the heavy oils, the oils may have been heated using, for example, steam injection. A thermal drive process for producing heavy oils typically employs an injection well and a production well. A hot fluid, typically steam, is introduced into the formation through the injection well. The injected steam heats the heavy oil, reducing its viscosity, and drives the heavy oil toward the production well. This process is problematic because the injected steam does not contact a large portion of the heavy oil, and the ambient temperature heavy oil is a very effective barrier to flow. The steam will also tend to over-ride the heavy oil and form a steam ceiling above the bulk of the heavy oil until the steam breaks through to the production well. After the break through injected steam will continue to bypass the heavy oil and go directly to the production well.
An attempt to make a steam drive operate in a heavy oil formation is described in U.S. Pat. No. 4,130,163.
The first viable method to stimulate production using steam was the “steam soak” or “huff and puff” method. In this method, steam is injected through a well into the reservoir for an injection phase, afterwhich the well is shut in for a soak period. After the soak period, oil is produced by artificial lift until the rate at which oil is produced decreases. Production is then stopped and steam injection is resumed. Initial injection periods are relatively short because the formation will not accept very much steam, and injection pressures are limited to prevent the steam from fracturing the formation to the extent the steam escapes from the near-wellbore region. The cycles are continued until the ratio of steam to oil becomes excessive. Canadian patent 1,144,064 describes the steam soak, or cyclic steam stimulation (“CSS”) method.
Another steam stimulation method is known as the steam assisted gravity drainage (“SAGD”) process. This process is described in U.S. Pat. No. 4,344,485. This process utilizes pairs of parallel horizontal wells that are stacked vertically. The upper well is a steam injection well and the lower well is a production well. Injection of steam from the top well creates a steam chest above the lower production well. As the heavy oil adjacent to the steam volume heats, it flows downward by the force of gravity and is then removed from the formation via the production well. The steam chest thereby gradually increases in volume and heavy oil is recovered from the formation.
Attempts have been made to improve the steam stimulation methods by adding hydrocarbon solvents to the steam. For example, U.S. Pat. No. 4,697,642 to Vogel discloses a process where steam and a vaporized solvent are used step-wise. First steam heats the viscous hydrocarbons and then a mixture of steam and vaporized solvent is added to further heat the viscous oil and further reduce the viscosity of the heavy oil by dilution of the heavy oil with condensed solvent. The steam-solvent vapor is “under saturated” in solvent, which is described as having a sufficiently low concentration of solvent in the steam so that steam will condense initially and the solvent will tend to stay in the vapor phase and thus be distributed further from the injection well. The steam and steam solvent mixture are injected near the top of the formation, and the production wells are separated from the injection wells and near the bottom of the reservoir. Injection of the steam and vaporized solvent at the top of the reservoir results in the formation of a hot zone at the top of the formation which is in contact with heavy oil below the hot zone, and the heavy oil, when heated and diluted with solvent, then flows to the production well.
Another suggestion to combine solvents with steam is found in U.S. Pat. No. 6,230,814 to Nasr et al. Nasr suggests that solvents either could be added continuously or sequenced with steam injection in SAGD, CSS or steam flood configurations. The solvent could be a wide variety of solvents including C₁to C₂₅hydrocarbons or nonaqueous fluids that may be miscible or immiscible with hydrocarbons being produced. The solvents preferably have an evaporation temperature within a range of 150° C. of the steam condensation temperature at the formation pressure. The solvents are preferably present in the steam solvent mixture at a concentration of between 0.1 and 5 percent liquid volume, wherein the liquid volume is the volume of the components in a liquid phase.

SUMMARY OF THE INVENTION

A method is provided for production of heavy oil from a reservoir containing heavy oil, the method comprising the steps of: providing a plurality of wells into the formation; injecting into the plurality of wells a mixture comprising steam and a solvent; ceasing injection of the mixture; producing a mixture of heavy oil, solvent and condensed steam from the plurality of wells after injection of steam has ceased: and after production of the mixture of heavy oil, solvent and condensate from at least one of the plurality of wells has declined to a predetermined rate, injecting into the at least one well a stream consisting essentially of steam while at least one other well continues to operate as a producing well.
The steps of providing a plurality of wells into the formation; injecting into the plurality of wells a mixture comprising steam and a solvent; ceasing injection of the mixture; producing a mixture of heavy oil, solvent and condensed steam from the plurality of wells after injection of steam has ceased, may be repeated, for example, two to eight times. This cyclic steam injection portion of the present invention could be continued until communication is observed between adjacent wells.
In one embodiment, the solvent may be a solvent comprising five or six carbon paraffinic hydrocarbons, and operation could leave a portion of asphaltenes in the formation rather than producing all of the asphaltenes originally in the heavy oil. In one embodiment, the process could produce a heavy oil containing ten percent by weight or less asphaltenes when the original heavy oil in place contained at least twelve percent by weight asphaltenes.

BRIEF DESCRIPTION OF THE FIGURES

FIGS. 1, 2, 3 and 4 are layouts of an example of a pattern for vertical and horizontal wells for practice of the present invention.

FIG. 5 is a plot of cumulative oil recovery factor as a function of time for the practice of the present invention compared to alternatives based on modeling.

FIG. 6 is a plot of cumulative oil to steam ratio as a function of time for the practice of the present invention compared to alternatives based on modeling.

DETAILED DESCRIPTION

FIG. 1 shows a layout of vertical wells useful for practice of the present invention. In this example, a seven spot pattern is shown with injection wells 101 surrounded by six producer wells 102. This pattern may be continued, and with many patterns provided, the ratio of production wells to injection wells would approach two. FIG. 2 shows a layout with a five spot pattern where every injection well is surrounded by four production wells, resulting in an ultimate ratio of production to injection wells approaching one for a large number of patterns. FIG. 3 shows a configuration where production wells have horizontal laterals 102 that form a square around vertical steam injection wells 101. FIG. 4 shows a configuration where parallel horizontal wells are utilized with injectors and producers alternating. Although the wells are identified as producers and injectors, in the practice of the present invention, the wells are all initially operated in a cyclic steam stimulation method to initially heat regions in the vicinity of the wells. After one or more cycles of steam injection and production, production is continued from wells designated as production wells, and steam, or another hot fluid, is injected from the wells designated as injection wells.
Wells may be provided for the practice of the present invention by methods known in the art for drilling and completion of wells in heavy oil containing formations. Production wells are preferably completed in the lower portion of the reservoir to minimize steam break through. Injection wells may be completed in the lower portion of the formation also because injected hot fluid such as steam strongly tend to over-ride bitumen, and there will be little steam bypassing directly to a production well through the lower portion of the formation when the formation between the wells contains heavy oil.
Alternative well patterns for the practice of the present invention include horizontal production wells located in a lower portion of the formation, and vertical injection wells.
The oil contained in the oil-bearing formation may have a dynamic viscosity under formation conditions (in particular, at temperatures within the temperature range of the formation) of at least 1 mPa s (1 cP), or at least 10 mPa s (10 cP), or at least 100 mPa s (100 cP), or at least 1000 mPa s (1000 cP), or at least 10000 mPa s (10000 cP). The oil contained in the oil-bearing formation may have a dynamic viscosity under formation temperature conditions of from 1 to 10000000 mPa s (1 to 10000000 cP). Typically, the heavy oil or bitumen in the formation may have a dynamic viscosity of at least 100 mPa s (100 cP), or at least 500 mPa s (500 cP), or at least 1000 mPa s (1000 cP).
The oil-bearing formation is a subterranean formation. The subterranean formation may be comprised of one or more porous matrix materials selected from the group consisting of a porous mineral matrix, a porous rock matrix, and a combination of a porous mineral matrix and a porous rock matrix, where the porous matrix material may be located beneath an overburden at a depth ranging from 50 meters to 6000 meters, or from 100 meters to 4000 meters, or from 200 meters to 2000 meters under the earth's surface. The subterranean formation may be a subsea subterranean formation. The subsea subterranean formation is preferably below less than 500 meters of water, and risers are preferably well insulated. For example, vacuum insulated risers would help reduce heat losses to the sea from the risers. Alternatively, foam insulation could be provided in an annulas between the production tubular and a riser casing.
The porous matrix material may be a consolidated matrix material in which at least a majority of the rock and/or mineral that forms the matrix material is consolidated such that the rock and/or mineral forms a mass in which substantially all of the rock and/or mineral is immobile when oil, solvent water, or other fluid is passed there through. At least 95 wt. % or at least 97 wt. %, or at least 99 wt. % of the rock and/or mineral may be immobile when oil, steam, water, or other fluid is passed there through so that any amount of rock or mineral material dislodged by the passage of the oil, steam, water, or other fluid is insufficient to render the formation impermeable to the flow of the steam, oil, water, or other fluid through the formation. Alternatively, the porous matrix material may be an unconsolidated matrix material in which at least a majority, or substantially all, of the rock and/or mineral that forms the matrix material is unconsolidated. The formation may have a permeability of from 0.0001 to 15 Darcies, or from 0.001 to 1 Darcy. The rock and/or mineral porous matrix material of the formation may be comprised of sandstone and/or a carbonate selected from dolomite, limestone, and mixtures thereof where the limestone may be microcrystalline or crystalline limestone and/or chalk.
Oil in the oil-bearing formation may be located in pores within the porous matrix material of the formation. The oil in the oil-bearing formation may be immobilized in the pores within the porous matrix material of the formation, by the low viscosity of the heavy oil and, for example, by capillary forces, by interaction of the oil with the pore surfaces, by the viscosity of the oil, or by interfacial tension between the oil and water in the formation.
The oil-bearing formation may also be comprised of water, which may be located in pores within the porous matrix material. The water in the formation may be connate water, water from a secondary or tertiary oil recovery process water-flood, or a mixture thereof. The water in the oil-bearing formation may be positioned to immobilize heavy oil within the pores. Contact of the steam of other hot fluids along with the solvent with the oil and water in the formation may mobilize the oil in the formation for production and recovery from the formation by freeing at least a portion of the oil from pores within the formation by reducing interfacial tension between water and oil in the formation and by reducing the viscosity of the oil in the formation.
Steam may be injected into a pattern in all wells initially in a known cyclic steam soak process for a sufficient number of cycles to provide communication between wells in a pattern. By communication, it is meant that steam, injected into a well at a pressure less than the fracture initiation pressure of the formation will be sufficient to force formation fluids into a production well at a significant rate. The number of cycles may be between two and eight. For each cycle, steam is injected until the rate at which steam can be injected does not exceed a predetermined rate, such as five to twenty five percent of the rate at which steam may initially be injected at a pressure that does not exceed formation fracture initiation pressure. For an initial cycle, this may be a period of one to four weeks. For subsequent cycles, this may be one to three months. After each injection period, the well may be shut in for a soak period. The soak period permits the heat from the steam to dissipate and transfer from the near wellbore region to formation and fluids within the formation further from the injection well. After the soak period, oil and condensate are produced from the wellbore by artificial lift means such as a sucker rod pump. When production of oil decreases to, for example, a predetermined fraction of initial production, the steam injection portion of the cycle may be initiated again. The predetermined fraction of initial production may be, for example, one to ten percent of initial oil production rate.
Whether communication between wells has been established may be tested by initiating injection into one well while surrounding wells continue in a production mode. When production in surrounding wells increases in response to injection being initiated in adjacent wells, communication has been established and a drive process may be initiated. The increase in production upon initiation of steam injection in an adjacent well is preferably an increase in production by a factor of ten to twenty five percent of the rate of fluid production near the end of a cycle of production.
It is also possible that cyclic steam injection cycles could be staggered so that at least some adjacent wells are operating in a steam injection mode while some adjacent wells are operated in a production mode.
During at least a portion of the cyclic steam soak cycles, the steam includes a solvent effective to further reduce the viscosity of the oil in the formation. The solvent may be a hydrocarbon having two to twenty carbons, or mixtures of such hydrocarbons. Alternatively, the solvent could be another component that is miscible with heavy oils. The solvent could be a diluent such as a mixture of mostly five or six carbon number hydrocarbons, or a natural gas condensate. The solvent could also be, for example, dimethyl sulfide, dimethyl ether, or another such sulfide, ether or alcohol solvents, may also be useful in the present invention. Dimethyl sulfide as a solvent useful for injection with steam is disclosed, for example, in U.S. patent application Ser. No. 61/836,521, the disclosure of which is incorporated herein by reference.
The choice of solvent for the practice of the present invention could be made to provide limited solubility of asphaltenes. Heavy oils may, in some instances, contain ten to fifteen percent by weight of asphaltenes. These asphaltenes are problematic with respect to processing and transportation of the produced heavy oils. In regions where heavy oil is abundant, these asphaltenes cause the heavy oils to be valued at a significant discount over, for example, West Texas intermediate, or other benchmark crude oils, and as a result be significantly discounted compared to oils containing lower concentrations of asphaltenes. When a paraffinic solvent, for example, a paraffinic five or six carbon solvent, is utilized in the practice of the present invention, a significant amount of asphaltenes may precipitate from the heavy oil-solvent mixture in the formation, and render more valuable produced oil. The more valuable produced oil may contain, for example, eight to eleven percent by weight, or for example, nine to ten percent by weight asphaltenes.
The steam solvent mixture may comprise between 85 and 99 percent steam and between 1 and 15 percent solvent based on a condensed volumes of steam and solvent. In another embodiment, the steam solvent mixture may comprise between 94 and 98 percent steam and between 2 and 6 percent solvent based on condensed volumes of steam and solvent.
In the practice of the present invention, after communication is established between wellbores, at least one well is operated as a continuous steam injection well, while at least one adjacent well is operated as a production well. In this phase of the process of the present invention, steam is injected without a significant amount of solvent included. Preferably the amount of solvent in the steam stream after a well is operating in a continuous steam injection mode is less than five volume percent solvent based on condensed liquid volume.
In an embodiment of the present invention, at least one of the wells that continue to operate as a production well extends to a lower portion of the reservoir. In addition, at least one of the wells that continues to operate as an injection well could extend to a upper portion of the reservoir. In another embodiment of the present invention, the production wells or the injection wells, or both, could be essentially horizontal wells. There may also be more production wells than injection wells. In one embodiment of the present invention, a ratio of production wells to injection wells could be between about two and about ten. In one embodiment, the ratio of production wells to injection wells could be about two, and the wells could be provided in essentially a triangular pattern. In this embodiment, the wells could be vertical wells.
Solvent of the present invention is preferably at least partially recovered from produced oils and recycled. In operations where diluent is added to produced oils to render the produced oils acceptable for transportation, for example by pipeline, diluent is a preferred solvent, and the recovery or separation of the solvent does not need to be complete, but only to the extent the produced oil meets specifications to render the produced oil acceptable for transportation.

EXAMPLE

An alternative of the present invention was modeled, along with some comparative examples. An element of symmetry model representing an inverted seven spot pattern with vertical wells was created to simulate different operational scenarios using the CMG STARS simulator. The CMG STARS simulator is a commercially available oil reservoir simulator available from Computer Modeling Group Ltd., 200, 1824 Crowchild Trail NW, Calgary, Alberta, T2M 3Y7, Canada. Geological and fluid properties selected were typical of the Peace River area, in Alberta, Canada. Five schemes were modeled and in each scheme, all wells were initially operated in a CSS mode for a number of cycles, and then the well in the center was used as a steam injection well while the other wells were operated as producers in a vertical steam drive mode. The five schemes were as follows:
1. Four CSS cycles, followed by a steam drive with no solvent
2. Four CSS cycles with solvent co-injected, followed by steam drive with no solvent.
3. Two CSS cycles with solvent, followed by two CSS cycles without solvent, then steam drive with no solvent.
4. Two CSS cycles with no solvent, followed by two CSS cycles with solvent, followed by steam drive with no solvent.
5. Four CSS cycles with no solvent, followed by a steam drive with solvent.
In all cases, where solvent was used, it was a six percent by weight of the steam stream, and the solvent used was a condensate stream. The condensate stream was modeled by using a combination of three components having the properties listed in the table below.


		Mol.	Liquid	Critical	Critical
	Mole	Wt.	density	temperature	pressure	Acentric	Cpen
Component	fraction	g/mol	Gm/cm³	° C.	bars	factor	cm³/mole

C4C5	43.376	71.655		191.136	33.91	0.2388	−5.64
C6C8	47.745	91.412	0.7266	246.766	30.04	0.3222	11.28
C9C20	8.879	165.292	0.8164	379.582	19.64	0.5888	26.5

FIG. 5 is a plot of the oil recovery factor and FIG. 6 is a plot of oil-steam ratio, both as a function of time for each of the five schemes, with the functions for the different schemes identified by the scheme number as described above. Oil recovery factor is the produced oil expressed as a percent of the original oil in place. From FIGS. 5 and 6 it can be seen that including solvent in initial cyclic steam soak cycles, and then utilizing a steam drive without solvent is the most effective use of the solvent.
From FIG. 5, it can be seen that ultimate production is greater for scheme 2 than for any of the other schemes, and even more significantly, this difference in production shows up early in the process. FIG. 6 also shows that for scheme 2, the oil to steam ratio is also greater, both at the end of the process, and in particular, in the period starting two years after initiation of the process. Because of the time value of money, the early production, and the early high oil to steam ratio is of considerable value.

Claims

What is claimed is:

1. A method for production of heavy oil from a reservoir containing heavy oil, the method comprising the steps of:

providing a plurality of wells into the formation;

injecting into the plurality of wells a mixture comprising steam and a solvent;

ceasing injection of the mixture;

producing a mixture of heavy oil, solvent and condensed steam from the plurality of wells after injection of steam has ceased: and

after production of the mixture of heavy oil, solvent and condensate from at least one of the plurality of wells has declined to a predetermined rate, injecting into the at least one well a stream consisting essentially of steam while at least one other well continues to operate as a producing well.

2. The method of claim 1, wherein the solvent comprises a hydrocarbon solvent.

3. The method of claim 1, wherein the solvent comprises a solvent comprising five and six carbon hydrocarbons.

4. The method of claim 1, wherein at least one of the wells that continue to operate as a producer well extends to a lower portion of the reservoir.

5. The method of claim 1, wherein at least one of the wells through which the stream consisting essentially of steam is injected extends to an upper portion of the reservoir.

6. The method of claim 1, wherein the steps of injecting into the plurality of wells a mixture comprising steam and a solvent; ceasing injection of the mixture; and producing a mixture of heavy oil, solvent and condensed steam from the plurality of wells after injection of steam has ceased; are repeated in this order for a plurality of cycles.

7. The method of claim 1, wherein the mixture comprising steam and a solvent comprises between 85 and 99 percent steam and between 1 and 15 percent solvent based on a condensed volumes of steam and solvent.

8. The method of claim 7, wherein the mixture comprising steam and a solvent comprises between 94 and 98 percent steam and between 2 and 6 percent solvent based on a condensed volumes of steam and solvent.

9. The method of claim 8, wherein the produced heavy oil comprises less than ten percent by weight asphaltenes.

10. The method of claim 1, wherein the wells, within the reservoir comprise essentially horizontal portions of wells.

11. The method of claim 10, wherein the well comprising an essentially horizontal portion of the well is a well that continues to operate as a production well, and the essentially horizontal portion extends through a lower portion of the reservoir.

12. The method of claim 10, wherein the well comprising an essentially horizontal portion of the well is a well through which the stream consisting essentially of steam is injected, and the essentially horizontal portion extends through a lower portion of the reservoir.

13. The method of claim 1, wherein the wells are essentially vertical wells.

14. The method of claim 13, wherein the ratio of wells that continue to operate as production wells to wells through which the stream consisting essentially of steam is injected is between about 2 and about 10.

15. The method of claim 14, wherein the ratio of wells that continue to operate as production wells to wells through which the stream consisting essentially of steam is injected is about two, and the wells are in an essentially hexagonal pattern with each injection well surrounded by six producing wells.